Comments on: Academic: Fossil fuel back-ups ‘may be the price to pay’ for renewableshttps://www.euractiv.com/section/electricity/interview/academic-fossil-fuel-back-ups-may-be-the-price-to-pay-for-renewables/
EU news and policy debates across languagesMon, 19 Nov 2018 19:49:10 +0000hourly1https://wordpress.org/?v=4.9.5By: re-updatehttps://www.euractiv.com/section/electricity/interview/academic-fossil-fuel-back-ups-may-be-the-price-to-pay-for-renewables/#comment-335926
Wed, 19 Sep 2018 05:16:01 +0000https://www.euractiv.com/?post_type=interview&p=1268299#comment-335926Two things to remember are the limited ability of HVDC transmission cables to carry large capacities. For example, the highest capacity in the world in 2012 was 2x660MW in Sweden.

A hydrogen pipeline is the same cost, and has a 15GW capacity. Natural gas pipelines can be upgraded for between 5-10% of the cost of a new HVDC route or pipeline.

The other thing to remember is the reduced cost of the electricity produced (as a result of the extra transmission costs) if the electrolyser is operating in a demand response role. This can be achieved in a few ways, but mainly if the electrolysers can switch on and off when required, and don’t need extensive transmission to the electrolysis plant. Obviously siting is a very important factor here, and other factors are also important – but reducing the cost of grid fees and taxes (plus revenue from other grid services) lowers the cost of electricity used to produce hydrogen. This is a good way to offset the 20% conversion loss associated with transforming electricity to hydrogen.

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Wed, 19 Sep 2018 03:46:35 +0000https://www.euractiv.com/?post_type=interview&p=1268299#comment-335925As Mr Pollitt mentions, there are three things an electricity operator can do to back up the variable nature of renewables.

1) The first is the capacity mechanism, where an under-utilised gas or perhaps coal generator is paid extra to fill in for this intermittency.

2) The second is demand response, where agreements are signed with large industrial users for example, to switch off their plant when there is a lack of supply from renewables.

3) The third option provided here is interconnection, where electricity is sourced from another member state.

As highlighted in this interview, there are a few problems with this situation because governments are not keen to forgo control of the national power supply to another country, which is the only realistic method at present of avoiding the large expense associated with keeping a very large amount of fossil back-up on standby, in case – for example – its not windy.

What is also mentioned is the need for storage – namely very large amounts of cheap storage that could be used intra-seasonally; so in this regard even pumped hydro-electric is not going to be enough at a Europe-wide scale. The capacity doesn’t exist, even if planning permission were given at scale.

So we are left with essentially one option; and how this is implemented is obviously important. First, there is the possibility of overbuilding very cheap renewables, and accepting a certain amount of curtailment. Costs can be minimised by building the initial electrolysis capacity to replace SMR hydrogen production; for example for ammonia and refinery hydrogen. This works out if CCS is required on top of the SMR cost – this is a direct use for hydrogen and requires few infrastructure changes. Gas pipelines can be upgraded to hydrogen for a 5-10% cost of building a new pipeline or transmission cable, and much more energy can be transported via pipeline than cable – so this is an option, however.

The second or later option is to both build a large amount of RES oversupply, and pair this to a large amount of electrolysis acting in this demand response role (4,500 hours per year is feasible as the capital cost of electrolysers will continue to decrease sharply) as outlined above.

However, what can be done here is to store some of this hydrogen in salt caverns (this is lower cost than pumped hydro-electric, at scale) or depleted gas wells, and then use this in any thermal generation plant; Holland are already converting the magnum 400MW facility to run hydrogen.

The round-trip efficiency of hydrogen conversion (approx 80% at best today) plus the efficiency of a CCGT (60% efficiency) does result in some energy loss. However, it is far cheaper than essentially doubling your entire electrical generating capacity (including quite a lot of excess transmission infrastructure) just on the off-chance you might need it.

A simple idea would be to mandate a certain percentage of demand response as a part of the capacity mechanism that must increase over time. It is up to the individual member state what they choose this demand response to be.

Ideally, this should be done with better rules regarding grid-fees and costs for electrolyser operators, and fewer (if any) taxes in order to expedite the growth of the industry. And the best way of doing this is to necessitate the use of electrolysis in this way. Really, electrolysis is the only way to maintain expansion of the renewables industry; there is absolutely no other way around this and the sooner people realise that batteries are not going to provide the scale of energy storage required, the sooner we can decarbonise both the electricity grid and large industrial process heat users, residential heat & hot water, and transport. Regulations are key to reducing the overheads on the electricity price paid.

Lots of major studies outlining the very large cost difference (in fact, the impossibility of an alternative) to electrifying building heat and using hydrogen.